U.S. patent number 7,464,754 [Application Number 11/175,956] was granted by the patent office on 2008-12-16 for co.sub.2 foamed well treatments.
This patent grant is currently assigned to Team CO2, Inc.. Invention is credited to Randal L. Decker, Michael D. Hyman, John J. Ridge.
United States Patent |
7,464,754 |
Decker , et al. |
December 16, 2008 |
CO.sub.2 foamed well treatments
Abstract
A composition and a method for treating a subterranean formation
with an injection liquid containing liquid carbon dioxide, a
treating liquid and optionally a foaming agent and/or methanol. The
treating liquid may be an acid, a corrosion inhibitor, a solvent or
a scale inhibitor.
Inventors: |
Decker; Randal L. (Midland,
TX), Hyman; Michael D. (Odessa, TX), Ridge; John J.
(Hobbs, NM) |
Assignee: |
Team CO2, Inc. (Midland,
TX)
|
Family
ID: |
40118620 |
Appl.
No.: |
11/175,956 |
Filed: |
July 7, 2005 |
Related U.S. Patent Documents
|
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
Issue Date |
|
|
60522537 |
Oct 11, 2004 |
|
|
|
|
Current U.S.
Class: |
166/263 |
Current CPC
Class: |
C09K
8/74 (20130101); C09K 8/94 (20130101); E21B
43/26 (20130101); Y10S 507/933 (20130101); Y10S
507/939 (20130101) |
Current International
Class: |
E21B
43/00 (20060101) |
References Cited
[Referenced By]
U.S. Patent Documents
Primary Examiner: Gay; Jennifer H
Assistant Examiner: Leonard; Kerry W
Attorney, Agent or Firm: Scott; F. Lindsey
Parent Case Text
RELATED APPLICATIONS
This application is entitled to and hereby claims the benefit of
the filing date of U.S. Provisional Application 60/522,537 filed
Oct. 11, 2004 by Randal L. Decker, Michael D. Hyman and John J.
Ridge and entitled "CO.sub.2 Foamed Acid."
Claims
What is claimed is:
1. A method for treating a subterranean formation penetrated from
an earth surface by at least one well, the method consisting
essentially of: a) blending a treating liquid and liquid carbon
dioxide to produce an injection liquid containing from about 51 to
about 95 weight percent liquid carbon dioxide and from about 5 to
about 49 weight percent treating liquid; b) injecting the injection
liquid into the subterranean formation through the at least one
well at a pressure below fracturing pressure in an amount
sufficient to treat a desired pore volume of the formation around
the at least one well; and, c) shutting in the well for at least
one hour.
2. The method of claim 1 wherein the carbon dioxide liquid in the
injection liquid is present in an amount from about 60 to about 80
weight percent.
3. The method of claim 1 wherein the treating liquid is selected
from aqueous organic or inorganic acids, aqueous corrosion
inhibitors and aqueous scale inhibitors or organic solvents.
4. The method of claim 3 wherein the treating fluid is an aqueous
acid selected from the group consisting of hydrochloric,
perchloric, nitric, sulfuric, phosphoric, hydrobromic,
hydrofluoric, hydriodic, citric, acetic and combinations
thereof.
5. The method of claim 3 wherein the treating liquid is an aqueous
organic or inorganic acid and the treating liquid contains from
about 5 to about 25 weight percent methanol.
6. The method of claim 3 wherein the treating fluid contains a
foaming agent.
7. The method of claim 3 wherein a quantity of a slug containing
from about 0 to about 100 weight percent liquid carbon dioxide and
from about 0 to about 100 weight percent water or crude oil is
injected after the injection of the injection liquid.
8. The method of claim 1 wherein the treating liquid contains a
corrosion inhibitor or an organic solvent.
9. The method of claim 1 wherein the treating liquid contains a
scale inhibitor.
10. The method of claim 1 wherein the well is shut in for a time
from about one hour to about 24 hours after injection of the
injection liquid.
11. The method of claim 1 wherein the injection fluid is injected
until a worm hole is created into a second well.
Description
FIELD OF THE INVENTION
The present invention relates to a composition and a method for
treating subterranean formations with acid, corrosion inhibitors,
scale inhibitors and the like.
BACKGROUND OF THE INVENTION
In many wells used for the production of oil, water, gas and the
like, it becomes necessary from time to time to treat such wells to
improve their permeability, to inject materials which can protect
metallic components of the well from corrosion and which can
protect the formation, especially the formation near the wellbore,
from scaling as a result of the production of fluids from the
well.
Many of these operations are used more frequently in oil wells and
in gas wells than in water wells.
In many instances, formations which contain valuable oil or gas
products may be so impermeable that the production of fluids from
these formations, either initially or after a period of production
is impractically slow. In such instances, a variety of techniques
have been used to improve the production rate. One technique is the
use of fracturing. This procedure requires that a pressure greater
than the formation pressure be imposed on the formation to create
fractures into the formation. While this technique has been
effective in many instances, it is limited in that it creates a
flow path only through the areas fractured. This leaves major
portions of the formation untreated to improve the
permeability.
Acid treatments have been used with and without foaming and
emulsifying agents to pass acids and the like into the formation.
Unfortunately, because of the limited permeability initially
present or present at the time of treatment, these materials are
difficult to inject into the formation for any substantial distance
without the injection of unduly large volumes of the treating
material.
As a result, a continuing effort has been directed to the
development of methods which are effective to inject treating
solutions into subterranean formations for a substantial distance
without the use of unduly large volumes of treating fluid.
SUMMARY OF THE INVENTION
The invention comprises a method for treating a subterranean
formation penetrated from an earth surface by at least one well,
the method comprising: blending a treating liquid and liquid carbon
dioxide (CO.sub.2) to produce an injection liquid containing from
about 51 to about 95 weight percent liquid CO.sub.2; injecting the
injection liquid into the subterranean formation; and, shutting in
the well for at least one hour.
The invention also comprises a composition for treating a
subterranean formation penetrated from an earth surface by at least
one well, the composition consisting essentially of: from about 51
to about 95 weight percent liquid CO.sub.2; and, from about 5 to
about 49 weight percent of a treating fluid.
The invention further includes a composition for treating a
subterranean formation penetrated from an earth surface by at least
one well, the composition comprising essentially of: from about 51
to about 95 weight percent liquid CO.sub.2; from about 5 to about
49 weight percent of a treating fluid; and, at least one of a
foaming agent and methanol.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1. is a schematic diagram of a well penetrating a subterranean
formation and adapted to treat the subterranean formation according
to the present invention;
FIG. 2. is a schematic diagram of a system for supplying the
composition of the present invention to a well;
FIG. 3. is a graph showing test results from the tests described
herein using the method of the present invention; and,
FIG. 4. is a graph showing the results achieved by the use of a
conventional process, which was tested in comparison to the process
of the present invention.
DETAILED DESCRIPTION OF THE INVENTION
In the description of the present invention, detailed descriptions
of the equipment used are not included since they are not necessary
to the description of the present invention and include well-known
equipment.
In FIG. 1 a subterranean formation 10, which is to be treated is
shown. Subterranean formation 10 underlies an overburden 12 and an
earth surface 14. Subterranean formation 10 is penetrated by a well
16, which includes tubing 18 and packers 20 to enable the injection
of a treating liquid into subterranean formation 10. Well 16, while
not described in detail, is a cased well and includes perforations
22, extending from an inside of the well into subterranean
formation 10. The bottom 24 of the well may be directly beneath
subterranean formation 10 or well 16 may extend into subterranean
formations lying beneath subterranean formation 10. If so, it is
desired that subterranean formation 10 be isolated, as well known
to those skilled in the art, for treatment.
In FIG. 2 a system 30 is shown for producing the composition of the
present invention for injection into well 16. The system comprises
a line 32, which is in fluid communication with a system for mixing
the components via line 32 and a check valve 54 and with well 16.
An acid pump 34 is shown in communication via a line 38 with an
acid supply 36 to supply acid via a line 40 at a desired pressure
and rate to line 32. Similarly, a CO.sub.2 pump 42 is shown in
communication with a CO.sub.2 supply 44 via a line 46 so that
liquid CO.sub.2 is desirably pumped via a line 48 into line 32.
Line 32 includes a line 50 and a pressure valve 52 for the relief
of pressure if desired. It will be understood that the acid supply
and the liquid CO.sub.2 supply could be originally provided at
pressure so that it would be unnecessary to have pumps for either
or both. Such variations are considered to be well within the scope
of the present invention.
According to the present invention, the treating fluid is mixed
with liquid CO.sub.2 to produce an injection liquid containing from
about 51 to about 95 weight percent liquid CO.sub.2. Preferably,
the liquid CO.sub.2 is present in a weight percentage from about 60
to about 80. The resulting injection fluid is injected into the
subterranean formation, which is then shut in for at least one
hour.
The treating fluid may be any well-treating material such as an
acid, a corrosion inhibitor, a solvent or a scale inhibitor. The
acid may be any suitable inorganic or organic acid, such as acids
selected from the group consisting of hydrochloric, perchloric,
nitric, sulfuric, phosphoric, hydrobromic, hydrofluoric, hydriodic,
citric, acetic and the like. Substantially any suitable acid can be
used, so long as it is compatible with the subterranean formation
and effective to dissolve small portions of the formation or
otherwise treat the formation as desired. The acid is mixed with
liquid CO.sub.2 in an amount from about 51 to about 95 weight
percent to produce a composition comprising about 51 to about 95
weight percent liquid CO.sub.2 and from about 5 to about 49 weight
percent acid. The acid may be provided as an aqueous solution such
as hydrochloric acid, which is frequently marketed in
concentrations of about 3.0 to about 28 volume percent in aqueous
solution. The weight references herein are to the acid in the form
in which it is supplied and injected. In other words, a 15 volume
percent hydrochloric acid in aqueous solution would be injected in
an amount equal to the stated weight percent of the aqueous
solution. Similar consideration is applied to the other acids
used.
The liquid CO.sub.2 is pumped at temperatures typically from about
-10 to about 5.degree. F., but may be pumped at temperatures from
about -15 to about 10.degree. F. The liquid CO.sub.2 may be pumped
at any suitable temperature and pressure at which the CO.sub.2 is
liquid. In other words, at higher pressures the temperature of the
liquid CO.sub.2 can be higher. The liquid CO.sub.2 and the acid are
physically mixed at the wellhead or at the pump discharge or the
like. The liquid CO.sub.2 is quite soluble in the acids and they
form a microemulsion that has a viscosity of about 20 to about 90
centipoises a lower relative permeability than plain acid. Testing
has indicated that plain acid has a relative permeability of about
4 millidarcy (md), while the CO.sub.2 foamed acid had a relative
permeability of 0.3 md for the acid component (a decrease of over
13 times or 1300%) while the relative permeability to the CO.sub.2
component was 0.2 md (a decrease of 20 times or 2000%) depending
upon the amount of liquid CO.sub.2 used. The much lower relative
permeability, and conversely higher viscosity, are critical in
reducing acid leak-off near the wellbore and thereby causing the
formation of a main flow channel for the acid to penetrate deeper
into the formation than non-foamed and/or low viscosity acids.
Generally speaking higher concentrations of liquid CO.sub.2 result
in a higher viscosity. This higher viscosity in the liquid
CO.sub.2/treating liquid microemulsion acts as a fluid loss agent
preventing leak off of the acid from the near wellbore. The
injection mixture forms one or more main flow channels (worm holes)
in the formation so that the microemulsion is pushed deeper into
the formation by the injection of lesser volumes than by the
injection of the acid or other material alone. The microemulsion is
forced deeper into the formation and reaches the areas of the
reservoir which have not been previously produced or depleted. Once
the microemulsion is in place, it tends to release the acid or
other treating material into the subterranean formation for its
interaction with the formation.
Desirably the acid optionally contains a foaming agent, which may
be any suitable foaming agent compatible with the subterranean
formation and the acid. For instance, some suitable foaming agents
are shown in U.S. Pat. No. 4,737,296 issued Apr. 12, 1998 to David
R. Watkins. The foaming agent may comprise a surfactant system as
disclosed in U.S. Pat. No. 4,650,000 issued Mar. 17, 1987 to Eva M.
Andreasson, et al. Additional foaming agents for foaming and
stabilizing acidizing fluids are disclosed in U.S. Pat. No.
6,555,505 issued Apr. 29, 2003 to Karen L. King, et al. These
patents are hereby incorporated in their entirety by reference.
As indicated previously, substantially any suitable foaming agent
compatible with the liquid CO.sub.2 and the treating fluid is
effective.
Further it is desirable that the acid contains quantities of
methanol. While the presence of methanol is optional, it is desired
that the methanol be present in an amount from about 5 to about 25
weight percent in the preferred composition.
The composition of the present invention can be used to inject
acid, organic solvents, scale inhibitors or corrosion inhibitors
into the formation. While acidizing is a commonly used treatment
which is greatly improved by the process and composition of the
present invention, it is noted that in some instances it is
desirable to inject organic solvents into a subterranean formation
to remove materials such as, for instance, asphaltenes deposited
near a production wellbore or at production sites within the
formation at which hydrocarbons are released into a permeable flow
path into a wellbore or the like. Similarly, scale inhibitors are
frequently injected for a substantial distance into the formation
to inhibit the formation of scale as water, oil or gas components
are released from the formation with the resulting formation of
scale in the pores from which they are released and through which
they pass. It is quite commonly necessary to inject a scale
inhibitor to maintain production in a subterranean formation. Such
scale inhibitor injections may be made after an acid treatment to
remove scale or the like, as known to those skilled in the art.
Further, corrosion inhibitors may desirably be injected to inhibit
corrosion of well components as fluids are produced through such
well components. In other words, the injection of the corrosion
inhibitors a substantial distance into the formation results in the
production of the corrosion inhibitor in trace quantities (which
may be sufficient to inhibit corrosion in the well equipment) with
the produced fluids
The method of the present invention comprises forming the
composition and injecting it into the subterranean formation and
thereafter shutting in the well for at least one hour.
As discussed previously, the microemulsion has much lower
interfacial tension and a higher viscosity than the acid without
the addition of the liquid CO.sub.2. These two qualities combine to
give the microemulsion the ability to penetrate deeply into the
subterranean formation. The mixture is pumped into the well at
pressures adequate to inject it into the formation. The quantity
injected will be determined by the pore volume which it is desired
to treat Particularly when acids are injected but in general with
all the materials, the treating materials will have an interaction
with the formation rock to dissolve, clean, treat or otherwise
modify the rock's ability to produce oil, gas, water or the like.
The mixture is pumped into the well at pressures below fracturing
pressure, but adequate to inject it into the formation as noted and
in a volume sufficient to treat the volume of the well which is
desired to be treated. If it is desired to push the composition
deeply into the well, a slug containing from 0 to about 100 weight
percent liquid CO.sub.2 and from about 0 to about 100 weight
percent water or crude oil may be used for injection into the well
to push the composition further into the formation. Desirably once
the composition is in place, it is left in place for a period of
time to absorb heat from the formation and generate foam. The foam
then moves out into formation portions which have not previously
been treated. Desirably the composition is left in place in the
formation for at least one hour and preferably up to 4 hours or
longer.
With the formation shut in, the foam is pushed into areas of the
formation which have not previously been treated from the flow path
created by the injection of the composition by the increased
pressure in the well.
Placing the composition in the subterranean formation, as discussed
above, when corrosion inhibitors or scale inhibitors are used,
results in positioning these materials in the formation so that
they can be produced back with the materials produced from the
formation to inhibit corrosion of well tubulars, which include
rods, tubing, casing, packers, bridge plugs and subsurface pumping
equipment and the like. Similarly, the use of scale inhibitors not
only inhibits scale formation in the formation but also on the same
components of the well.
The composition of the present invention comprises from about 51 to
about 95 weight percent liquid CO.sub.2 and from about 5 to about
49 weight percent of a treating fluid. The treating fluid, as
indicated previously, may be an acid, an inorganic solvent, a scale
inhibitor or a corrosion inhibitor, or any other desired treating
fluid. The present method and composition are directed to a carrier
composition which is useful to carry treating fluids into a
subterranean formation more efficiently and more effectively than
has been previously possible.
Desirably the composition contains from about 60 to about 80 weight
percent CO.sub.2 in the composition. As indicated, increased
quantities of liquid CO.sub.2 result in increased viscosity and
more effective movement in a slug fashion through the
formation.
Desirably in the composition, the treating liquid is at least one
of an inorganic acid, an organic acid, an organic solvent, a scale
inhibitor or a corrosion inhibitor or the like. Typically the acid
is selected from the group consisting of hydrochloric, perchloric,
nitric, sulfuric, phosphoric, hydrobromic, hydrofluoric, hydriodic,
citric, acetic and combinations thereof. Further the composition
also desirably contains from about 5 to about 25 weight percent
methanol and from about 0.2 to about 1.0 weight percent of a
foaming agent. The composition typically has a viscosity from about
20 to about 90 centipoise and preferably from about 60 to about 90
centipoise.
EXPERIMENTAL PROCEDURES
1. Formation samples were extracted of hydrocarbons, leached of
salts and dried until the weight stabilized. Basic properties,
including grain density, pore volume and permeability to air were
measured at 1400 psi net confining stress.
2. Synthetic formation brine was prepared based on the analysis of
the formation brine using deionized water and reagent grade
chemicals. The brine was filtered to 0.45 microns and degassed.
Fluid parameters including viscosity and density were measured at
135.degree. F.
3. Samples were evacuated of air and pressure saturated with
synthetic formation brine. Saturation percent was calculated
gravimetrically.
4. Each sample was loaded into a centrifuge in an
air-displacing-brine configuration. The samples were desaturated at
a capillary pressure equivalent to 200 psi. Initial water
saturation was calculated gravimetrically.
5. Each sample was briefly saturated with depolarized kerosene.
6. Each sample was loaded into a hydrostatic coreholder and 1400
psi net confining stress was applied. A pore pressure of 200 psi
was established by passing depolarized kerosene through the system
and around the sample. Coreholder, sample and system were elevated
to 135.degree. F. while maintaining net confining stress and pore
pressure and allowed to equilibrate for four (4) hours.
7. Crude oil was injected through each sample at a constant rate to
displace the depolarized kerosene. Once the depolarized kerosene
was displaced and the differential pressure stabilized, effective
permeability to oil at initial water saturation was determined.
8. The temperature was reduced to ambient while bypassing crude oil
through the system and around the sample. The pore pressure was
slowly removed and each sample was unloaded from the
coreholder.
9. Each sample was loaded into an aging vessel, covered with crude
oil and pressurized to 500 psi. The samples were allowed to age for
one week at 135.degree. F. while temperature and pressure were
monitored. After wetability restoration, the vessel was cooled to
ambient temperature and the pressure was slowly lowered. Each
sample was removed for flow testing.
10. Each sample was loaded into a hydrostatic coreholder and 1400
psi net confining stress was applied. A pore pressure of 3800 psi
was established by passing depolarized kerosene through a system
and around the sample while maintaining 1400 psi net confiding
stress. Coreholder, sample and system were elevated to 135.degree.
F. while maintaining net confining stress and pore pressure and
allowed to equilibrate for four (4) hours.
11. Synthetic formation brine was injected through each sample at a
constant rate, while collecting produced volumes of water and oil
and monitoring differential pressure and elapsed time until a
water-cut of 99.95% or greater was observed. Effective permeability
to brine at residual oil saturation was determined at two injection
pressures.
12. Fifteen percent hydrochloric acid and additives (sample 3C)
were injected in the injection direction at a constant rate of 0.25
cc/min. Differential pressure, injected and produced volumes and
injection pressure were recorded versus time. When a sudden and
sharp decrease in differential pressure was noted, a worm hole had
been established (FIG. 3).
13. Fifteen percent hydrochloric acid, additives, foamer and carbon
dioxide were co-injected through a second sample (sample 3) in the
injection direction at a constant rate of 0.25 cc/min. They were
co-injected at an 80:20 carbon dioxide to acid ratio. Differential
pressure, injected and produced volumes and injection pressure were
recorded versus time. When a sudden and sharp decrease in
differential pressure was noted, a worm hole had been established
(FIG. 4).
14. The test system and sample were allowed to cool to ambient
temperature. Pore pressure and net confining stress were slowly
removed. Each sample was unloaded from the hydrostatic coreholder,
weighed, extracted of hydrocarbons, leached of salts and dried to a
constant weight.
15. Permeability versus throughput data was calculated based upon
sample and fluid parameters and data collected using Darcy's Law.
Worm hole penetration is calculated from the total amount of fluid
injected versus time.
By the method and by the use of the composition of the present
invention as shown in FIG. 4, it will be noted that by the use of
the composition of the present invention, the formation as treated
has exhibited a comparable initial permeability to the tests shown
in FIG. 4 with injection being at the differential pressure shown.
By the injection of only four pore volumes of treating solution
into the formation, the treating composition has passed through the
formation leaving a treated zone in the formation from the
injection point to a receiving well so that the formation is
treated throughout with only four pore volumes of the composition.
By direct comparison, when an aqueous acid alone is used, as shown
in FIG. 3, it required 36 pore volumes of material to position the
injected acid completely through the formation to a receiving well.
The invention represents a significant improvement in the expense
and the effectiveness of the acid to treat the subterranean
formation.
While the present invention has been described by reference to
certain of its preferred embodiments, it is pointed out that the
embodiments described are illustrative rather than limiting in
nature and that many variations and modifications are possible
within the scope of the present invention. Many such variations and
modifications may be considered obvious and desirable by those
skilled in the art based upon a review of the foregoing description
of preferred embodiments.
* * * * *